Process for producing mineral oil from an underground deposit

ABSTRACT

A process for producing mineral oil, in which an aqueous flooding medium comprising water, a glucan, urea and optionally surfactants is injected into the mineral oil formation and mineral oil is withdrawn from the formation through at least one production well, wherein the formation has a temperature of at least 60° C. The formulation forms in situ foams in the formation under the influence of the formation temperature.

The present invention relates to a process for producing mineral oil, in which an aqueous flooding medium comprising water, a glucan, urea and optionally surfactants is injected into the mineral oil formation and mineral oil is withdrawn from the formation through at least one production well, wherein the formation has a temperature of at least 60° C. The formulation forms in situ foams in the formation under the influence of the formation temperature, and also gases which lead to formation of an alkaline bank in the oil-bearing stratum.

In natural mineral oil deposits, mineral oil occurs in cavities of porous reservoir rocks which are closed off from the surface of the earth by impervious covering layers. In addition to mineral oil, including the natural gas dissolved therein in a natural manner, a deposit further comprises water with a higher or lower salt content. The cavities may be very fine cavities, capillaries, pores or the like, for example those having a diameter of only approx. 1 μm; the formation may additionally also have regions with pores of greater diameter and/or natural fractures or fissures.

After the well has been sunk into the oil-bearing strata, the oil at first flows to the production wells owing to the natural deposit pressure, and erupts from the surface of the earth. This phase of mineral oil production is referred to by the person skilled in the art as primary production. In the case of poor deposit conditions, for example a high oil viscosity, rapidly declining deposit pressure or high flow resistances in the oil-bearing strata, eruptive production rapidly ceases. With primary production, it is possible on average to extract only 2 to 10% of the oil originally present in the deposit. In the case of higher-viscosity mineral oils, eruptive production is generally completely impossible.

In order to enhance the yield, what are known as secondary production processes are therefore used.

The most commonly used process in secondary mineral oil production is water flooding. This involves injecting water through the injection wells into the oil-bearing strata. This artificially increases the deposit pressure and forces the oil out of the injection wells to the production wells. Water flooding in the case of production of relatively high-viscosity mineral oils can enhance the yield level only slightly.

In the ideal case of water flooding, a water front proceeding from the injection well should force the oil homogeneously over the entire mineral oil formation to the production well. In practice, a mineral oil formation, however, has regions with different levels of flow resistance. In addition to oil-saturated reservoir rocks which have fine porosity and a high flow resistance for water, there also exist regions with low flow resistance for water, for example natural or synthetic fractures or fissures or very permeable regions in the reservoir rock. Such permeable regions may also be regions from which oil has already been substantially recovered by the water. In the course of water flooding, the flooding water injected naturally flows principally through flow paths with low flow resistance from the injection well to the production well. The consequences of this are that the oil-saturated deposit regions with fine porosity and high flow resistance are not flooded, and that increasingly more water and less mineral oil is produced via the production wells. In this context, the person skilled in the art refers to “watering out of production”. The effects mentioned are particularly marked in the case of relatively high-viscosity mineral oils. The higher the mineral oil viscosity, the more probable is rapid watering out of production.

In order to counteract the above-described adverse effects in the production of mineral oils, especially viscous mineral oils, various measures are known in the prior art.

For example, the preferred flow paths for injected flooding water can be blocked. For this purpose, it is possible to use gel-forming formulations which are of comparatively low viscosity before injection and form highly viscous gels in the formation after injection. This blocks preferred flow paths for the flooding water and diverts the water into regions from which oil has yet to be recovered. Such measures are also known as “Conformance Control” or ‘Water shut-off’. Altunina, L. K., Kuvshinov, V. A. “Improved Oil Recovery of High-Viscosity Oil Pools with Physicochemical Methods and Thermal-Steam Treatments”, Oil & Gas Science and Technology, Vol. 63 (2008), No. 1, pages 37 to 48 disclose the use of cellulose ethers for mineral oil production. Aqueous solutions of cellulose ethers are of relatively low viscosity at room temperature and do not form highly viscous gels until relatively high temperatures. It is possible to add urea or ammonium thiocyanate to the cellulose ether formulations in order to influence the gel formation temperature.

It is additionally known that suitable measures can be taken to match the viscosities of the water and oil phases to one another. For this purpose, the oil viscosity can be reduced and/or the viscosity of the aqueous flooding medium can be increased. Measures for reduction of the oil viscosity are, for example, CO₂ flooding and steam flooding. CO₂ flooding reduces the oil viscosity by the action of the CO₂, and steam flooding by the increase in the temperature. The viscosity of the aqueous flooding media can be enhanced by the addition of suitable viscosity-enhancing additives. Examples thereof include polymer flooding, in which the viscosity of the aqueous phase is increased by the addition of polymers, or foam flooding.

For polymer flooding, a multitude of different thickening water-soluble polymers have been proposed, both synthetic polymers, for example polyacrylamide or copolymers of acrylamide and other monomers, more particularly monomers having sulfo groups, and polymers of natural origin, for example glucosylglucans, xanthans or diutans. Glucosylglucans are branched homopolysaccharides formed from glucose units. The preparation of such glucosylglucans and the use thereof for mineral oil production is disclosed, for example, in EP 271 907 A2, EP 504 673 A1, DE 40 12 238 A1 and WO 03/016545. Glucosylglucans have a high thermal stability and are therefore especially suitable for mineral oil deposits with high deposit temperatures. Our prior application EP 11154670.1 discloses a process for producing mineral oil from deposits with a deposit temperature of at least 70° C. using glucans.

Altunina, L.K., Kuvshinov, V.A. and Stasyeva, L. A. “Thermoreversible Polymer Gels for EOR”, in Recent Innovations in Oil and Gas Recovery, István Lakatos (Ed.)—Akadémiai Kiadó, Budapest, Progress in Oilfield Chemistry, Vol. 8, pages 133 to 144, 2009 disclose the use of methylcellulose gels for tertiary mineral oil production. The gels may comprise additives to increase the gel formation temperature, for example ethanol, ammonium thiocyanate, thiourea or urea.

Various techniques for foam flooding are disclosed, for example, in the publications cited below:

U.S. Pat. No. 5,074,358 and U.S. Pat. No. 5,363,915 disclose processes for tertiary mineral oil production, in which foams are used. The gases used for foaming may, for example, be CO₂, N₂ or CH₄. The foam can be formed either by alternately injecting gas and foam-forming formulations into the formation or by forming a foam and injecting the foam into the formation (see, for example, U.S. Pat. No. 5,363,915, column 6, lines 3 ff.).

Drozdov A. N., Telkov V. P., Egorov Yu. A. et al. disclose, in “Solution of problems of water-gas influence (WGI) on the layer using jet and electrical centrifugal pumping technology”—Society of Petroleum Engineers SPE Paper 117380, the injection of a mixture of water, natural gas and surfactant into a mineral oil deposit to increase the yield.

Hombrook M. W., Dehgham K., Qadur S. Ostermann K. D., Ogbe D. Q. “Effects of CO ₂ addition to steam on recovery of west sak crude oil” SPE, Reservoir Eng.—1991—6 N^(o) 3, p. 278-286 disclose a process in which a mixture of steam and CO₂ is injected into a mineral oil deposit.

U.S. Pat. No. 5,307,878 likewise discloses a process for tertiary mineral oil production, in which foams are used. To stabilize the foam, an essentially uncrosslinked polymer is additionally used. The polymers mentioned are a multitude of different polymers, for example synthetic polymers such as polyvinyl alcohol, polyethylene oxide, polyvinylpyrrolidone, polyacrylamide, partly hydrolyzed polyacrylamide or natural polymers such as xanthan, scleroglucan, hydroxypropylcellulose or hydroxyethylcellulose.

RU 2 190 091 C2 discloses a multistage process for tertiary mineral oil production, in which a polymer solution is first injected, then a foam-forming formulation and a gas, and then a polymer solution again. The aqueous foam-forming formulation comprises water, alkali, a surfactant and a water-soluble polymer with M_(n) 300 to 30,000 g/mol. The polymer may, for example, be xanthan, guar gum, polyacrylamide or partly hydrolyzed polyacrylamide.

In the case of separate injection of foam-forming formulations and gases to form foams in the deposit, the gases have to mix with the foam-forming formulation underground after injection into the deposit, in order to form a foam. However, homogeneous and complete mixing underground is generally impossible to achieve. Instead, a considerable portion of the foam-forming formulations does not come into contact with the gases, such that the homogeneous foam bank is not formed in the formation. The gases escape predominantly into the higher regions of the deposit, and the liquid into the lower regions. The mixing of the gases with liquid in storage zones relatively far from the injector (20-100 m) is therefore barely possible in the case of serial pumping of foam-forming formulations and gases. The technique of forming the foam at the surface is complicated, requires additional equipment and also does not guarantee that the foam reaches regions of the deposit relatively far-removed from the injector.

There are therefore known techniques for forming gases in situ in the deposit by means of suitable measures to form foams, rather than injecting them.

RU 2 361 074 C2 discloses a process in which an aqueous solution of urea, ammonium nitrate, ammonium thiocyanate and surfactants, and also—alternately therewith—steam are injected into a mineral oil deposit. In the deposit, the urea is hydrolyzed to form CO₂ and ammonia in the deposit, which bring about an enhancement of oil recovery.

Bocksermann A., Kotscheschkov A., Tarasov A. disclose, in “Vervollkommnung der thermischen Methoden zur Entölungssteigerung der Erdöllagerstätten”[Enhancement of the thermal methods for increasing oil recovery from mineral oil deposits], Russian Institute for Scientific and Technical Information, “Development of oil and gas deposits” series, volume 24, Moscow 1993, a process for oil production in which water flooding or steam flooding is combined with cyclic pumping of aqueous urea solutions. Under the action of the deposit temperature or the steam temperature, the urea is hydrolyzed to CO₂ and ammonia. The gases released promote the oil recovery from the mineral oil deposit.

However, foam formation is frequently also inadequate in the case of the methods mentioned. The mixture of water and urea injected can mix with deposit water present in the deposit after injection and is diluted as a result. This complicates foam formation and completely prevents it in the case of excessive dilution.

It was an object of the invention to provide an improved process for producing oil by means of foam flooding.

Accordingly, a process has been for producing mineral oil from an underground mineral oil deposit into which at least one production well and at least one injection well have been sunk, each of which is connected to the deposit, said process comprising at least one process step (B) in which mineral oil is produced by injection of an aqueous flooding medium comprising water-soluble thickening polymers through the injection well and withdrawing mineral oil through the production well, wherein the temperature during process step (B) at least in a partial region of the mineral oil formation between the injection and production wells is at least 60° C. and wherein the aqueous flooding medium comprises, as well as water, at least

-   -   a glucan (G) with a β-1,3-glycosidically linked main chain and         side groups β-1,6-glycosidically bonded thereto, said glucan         having a weight-average molecular weight M_(w) of 1.5*10⁶ to         25*10⁶ g/mol, and     -   urea.

INDEX OF FIGURES

FIG. 1 Dependence of the viscosity of the glucan (G) No. P1 and of comparative polymers V1 and V2 on concentration

FIG. 2 Temperature dependence of the viscosity of the glucan (G) No. P1 and of the comparative polymers V1, V2 and V3 in ultrapure water

FIG. 3 Temperature dependence of the viscosity of the glucan (G) No. P1 and of the comparative polymers P1, V1, V2 and V3 in deposit water

FIG. 4 Schematic diagram of mineral oil production by means of the process according to the invention

FIG. 5 Schematic diagram of mineral oil production by means of the process according to the invention after the performance of conformance control measures

FIG. 6 Formation of CO₂ by decomposition of urea in a glucan (G) solution at 90° C.

The following specific details of the invention are given:

PROCESS PRINCIPLE

To execute the process according to the invention, at least one production well and at least one injection well are sunk into the mineral oil deposit. In general, a deposit is provided with several injection wells and with several production wells.

Through the injection wells, flooding media, for example aqueous flooding media or steam, can be injected into the deposit. As a result of the pressure generated by the flooding media injected, the mineral oil flows in the direction of the production well and is produced through the production well. The term “mineral oil” in this context does not of course mean only single-phase oil; instead, the term also comprises the typical crude oil-deposit water emulsions.

The mineral oil may in principle be any kind of mineral oil. However, the deposits may preferably be those comprising viscous mineral oil. The mineral oil present in the deposit may, for example, have a viscosity η_(oil) of at least 30 mPa*s, (measured at the natural deposit temperature).

In addition to the oil, the mineral oil formation may comprise deposit water with a greater or lesser salt content. The salts in the deposit water may especially be alkali metal salts and alkaline earth metal salts. Examples of typical cations comprise Na⁺, K⁺, Mg²⁺ or Ca²⁺, and examples of typical anions comprise chloride, bromide, hydrogencarbonate, sulfate or borate. The salt content of the deposit water may be 20,000 ppm to 350,000 ppm (parts by weight based on the sum of all components of the deposit water), for example 100,000 ppm to 250,000 ppm. The amount of alkaline earth metal ions, especially of Mg²⁺ and Ca²⁺ ions, may be 1000 to 53 000 ppm.

In general, deposit water comprises one or more alkali metal ions, especially Na⁺ ions. In addition, alkaline earth metal ions may also be present, in which case the weight ratio of alkali metal ions/alkaline earth metal ions is generally ≧2, preferably ≧3. The anions present are generally at least one or more than one halide ion, especially at least chloride ions. In general, the amount of Cl⁻ is at least 50% by weight, preferably at least 80% by weight, based on the sum of all anions.

The process according to the invention comprises at least one process step (B), in which an aqueous flooding medium comprising at least water, a glucan (G) with a β-1,3-glycosidically linked main chain and side groups β-1,6-glycosidically bonded thereto, and urea is used. After injection into the deposit, the urea decomposes under the influence of the deposit temperature to form CO₂ and NH₃.

The process may optionally comprise at least one additional process step (A) which is executed before a process step (B), and in which flooding media are likewise injected into the deposit. The flooding medium is preferably either an aqueous flooding medium (process step (A1)) or steam (process step (A2)).

The process may optionally comprise at least one additional process step (C) which is executed after a process step (B), and in which flooding media are likewise injected into the deposit. The flooding medium is preferably either an aqueous flooding medium (process step (C1)) or steam (process step (C2)).

It will be appreciated that process step (B) and the optional process steps (A) and (C) can be executed more than once. They can, for example, be executed repeatedly in a cycle.

The process may also optionally comprise further process steps. This may involve a further process step (D). In step (D), a formulation of a thermogel thickened by means of a glucan (G) is injected, i.e. a formulation which, after injection, can form highly viscous gels under the influence of the formation temperature. This can block permeable regions of the formation, such that subsequently injected aqueous flooding media have to flow via new flow paths. This can mobilize further oil.

According to the invention, the temperature during process step (B), at least in a partial region of the mineral oil formation between the injection and production wells, is at least 60° C., preferably at least 70° C., more preferably at least 80° C. and, for example, at least 90° C. It should not exceed 150° C., preferably 135° C. and more preferably 120° C. It may be 60° C. to 150° C., especially 70° C. to 140° C., preferably 75° C. to 135° C. and more preferably 80° C. to 120° C.

The term “region between the injection and production wells” here means that part of the underground formation which is covered by the flooding operation in the course of process step (B), i.e. those regions through which the injected flooding media and/or the mineral oil mobilized as a result flow from the injection well to the production well during the flooding operation. Naturally, this is not the shortest path from the injection well to the production well. Instead, the flow paths are guided by the geological conditions in the formation, and they may therefore also be longer. According to the invention, the temperature at least in a partial region thereof may have the above values. Preferably, the temperature in the entire region of the injection and production wells may have the values mentioned. The temperature in the entire region between the injection and production wells should not exceed the abovementioned maximum temperatures of 150° C., preferably 135° C. and more preferably 120° C.

The temperatures mentioned may be the natural deposit temperature. The natural deposit temperature can, however, be altered by flooding operations preceding process step (B). If the deposit is flooded, for example, with cold water for a prolonged period before performance of process step (B), the temperature of the deposit is lowered proceeding from the injection well, in which case the temperature approaches the natural deposit temperature again with increasing distance from the injection well. If the deposit, in contrast, is flooded with hot steam for a prolonged period before the performance of process step (B), the temperature of the deposit is increased proceeding from the injection well.

The temperature distribution in the formation can optionally be determined before the performance of process step (B). Methods for determination of the temperature distribution in a mineral oil deposit are known in principle to those skilled in the art. The temperature distribution is generally undertaken from temperature measurements at particular sites in the formation in combination with simulation calculations, the latter taking into account factors including amounts of heat introduced into the formation and the amounts of heat removed from the formation.

Process According to the Invention

Glucans Used

“Glucans” are understood by the person skilled in the art to mean homopolysaccharides formed exclusively from glucose units. According to the invention, a specific class of glucan is used, specifically those glucans which comprise a main chain formed from β-1,3-glycosidically linked glucose units, and side groups which are formed from glucose units and are β-1,6-glycosidically linked thereto. The side groups preferably consist of a single β-1,6-glycosidically attached glucose unit, with—viewed statistically—every third unit of the main chain β-1,6-glycosidically linked to a further glucose unit.

Such glucans are secreted by specific fungal strains, and corresponding fungal strains are known to those skilled in the art. Examples comprise Schizophyllum commune, Sclerotium rolfsii, Sclerotium glucanicum, Monilinia fructigena, Lentinula edodes or Botrytis cinera. Suitable fungal strains are specified, for example, in EP 271 907 A2 and EP 504 673 A1, claim 1 of each. The fungal strains used are preferably Schizophyllum commune or Sclerotium rolfsii and more preferably Schizophyllum commune, which secretes a glucan in which, on a main chain formed from β-1,3-glycosidically linked glucose units—viewed statistically—every third unit of the main chain is β-1,6-glycosidically linked to a further glucose unit; in other words, the glucan is preferably what is called schizophyllan. The glucans used for the invention have a weight-average molecular weight Mw of approx. 1.5 to approx. 25*10⁶ g/mol, especially 2 to approx. 15*10⁶ g/mol.

The production of such glucans is known in principle. For production, the fungi are fermented in a suitable aqueous nutrient medium. In the course of fermentation, the fungi secrete the abovementioned class of glucans into the aqueous fermentation broth, and an aqueous polymer solution can be removed from the aqueous fermentation broth. Processes for fermenting such fungal strains are known in principle to those skilled in the art, for example from EP 271 907 A2, EP 504 673 A1, DE 40 12 238 A1, WO 03/016545 A2 and Udo Rau, Viosynthese, Produktion and Eigenschaften von extrazellulären Pilz-Glucanen” [Biosynthesis, Production and Properties of Extracellular Fungal Glucans], Habilitation Thesis, Technische Universität Braunschweig, Shaker Verlag Aachen 1997”, each of which also mentions suitable nutrient media. The fermentation systems may be continuous or batchwise systems.

An aqueous solution comprising glucans is ultimately removed from the fermentation broth which comprises dissolved glucans and biomass (fungal cells, with or without cell constituents), leaving an aqueous fermentation broth in which the biomass has a higher concentration than before. The removal can especially be effected by means of single-stage or multistage filtration, or by means of centrifugation. It will be appreciated that it is also possible to combine several removal steps with one another.

In the removal, it should be ensured that the biomass is very substantially retained. Biomass remaining in the filtrate can block fine pores of the mineral oil formation. The quality of the filtrate can be determined in a manner known in principle by means of the millipore filtration ratio (MPFR). The test method is outlined in EP 271 907 B1, page 11, lines 24 to 48. The MPFR of the filtrates should be at a minimum, and especially 1.001 to 3, preferably 1.01 to 2.0.

The filtration can preferably be undertaken by means of crossflow filtration, especially crossflow microfiltration. The crossflow microfiltration process is known in principle to the person skilled in the art and is described, for example, in “Melin, Rautenbach, Membranverfahren [Membrane processes], Springer-Verlag, 3rd edition, 2007, page 309 to page 366′. “Microfiltration” is understood by the person skilled in the art here to mean the removal of particles of a size between approx. 0.1 μm and approx. 10 μm. A process for producing glucans using crossflow filtration is disclosed in WO 2011/082973 A2.

The glucans can be removed from the filtrate obtained. Preferably, however, the glucans are not removed, and the resulting aqueous glucan solution is instead used directly for production of the flooding media for process step (B). The concentration of the glucan solutions obtained may, for example, be 5 to 25 g/l.

Solutions of the glucans (G) used in accordance with the invention already have a high viscosity at low concentrations, the viscosity within the temperature range from room temperature to approx. 140° C. being substantially independent of the temperature and substantially independent of the salt content in the formation water (see FIG. 2 and FIG. 3). Details of this are given in the examples section.

Flooding Medium for Process Step (B)

In process step (B), an aqueous flooding medium comprising, as well as water, at least one glucan (G) and urea is used.

As well as water, it is optionally also possible to use water-miscible organic solvents in small amounts, but at least 85% by weight, preferably at least 95% by weight, of the solvents used should be water. Preference is given to using exclusively water as the solvent.

The water may be fresh water or else water comprising salts. For example, the water may be seawater or partly desalinated seawater, or all or some thereof may be salt-containing deposit water which can be injected back into the deposit in this way.

The concentration of the glucan (G) is guided by the desired viscosity of the flooding medium for process step (B). The viscosity of glucan solutions at different concentrations is shown in FIG. 1, the dependence of the viscosity as a function of temperature in FIGS. 2 and 3.

The viscosity of the aqueous flooding medium for process step (B) depends predominantly on the type and concentration of glucan (G) used. It should be matched to the viscosity of the oil phase and can be determined more accurately with the aid of the ratio (R) between the flooding medium mobility (M_(w)) and the oil mobility (M_(o)):

R=M _(w) /M _(o)=(k _(nw)/μ_(w))/(k _(nw)/μ_(o)),

k_(rw)—relative permeability of the formation for the aqueous flooding medium,

k_(ro)—relative permeability of the formation for mineral oil,

μ_(o)—mineral oil viscosity,

μ_(w)—viscosity of the aqueous flooding medium.

μ_(w) relates here to the aqueous flooding medium under use conditions in the formation. Ideally set to values <1. At R<1, the person skilled in the art expects piston-like displacement of the oil. The optimal ratio (R) between the water mobility (M_(w)) and the oil mobility (M_(o)) is usually not achievable, especially for highly viscous oils, because unrealistically high injection pressures have to be developed. It is therefore also possible to work with R values>1. However, even a relatively small increase in the viscosity of the water phase by means of the glucan tends to improve the mineral oil yield.

In general, the concentration of the glucan (G) is 0.1 g/l to 20 g/l, preferably 0.1 to 5 g/l and more preferably 0.1 to 2 g/l.

According to the invention, the aqueous formulation further comprises urea.

Urea (H₂N—CO—NH₂) hydrolyzes in water at elevated temperature to give CO₂ and ammonia. By its nature, the hydrolysis reaction is temperature-dependent, and the higher the temperature, the more rapidly it proceeds. If the urea is hydrolyzed under the influence of the deposit temperature in the formation, the gases naturally form directly in the formation, and thus foams can form in the formation.

The amount of urea in the flooding medium for execution of process step (B) is generally 15 to 350 g/l of the formulation, especially 15 g/l to 300 g/l, preferably 30 g/l to 250 g/l and more preferably 50 g/l to 250 g/l.

Optionally, the formulation may further comprise at least one ammonium salt. Examples of suitable ammonium salts comprise ammonium nitrate and ammonium chloride in particular.

The amount of the ammonium salts in the flooding medium for execution of process step (B) is generally 20 to 300 g/l of the formulation, especially 20 g/l to 250 g/l, preferably 30 g/l to 250 g/l and more preferably 50 g/l to 250 g/l.

Optionally, the formulation may further comprise at least one surfactant. Suitable surfactants for this purpose are especially foam-forming surfactants. Foam-forming surfactants have a certain film formation capacity and thus promote the formation of foams. Examples of foam-forming surfactants are known in principle to those skilled in the art. Examples comprise anionic, cationic or nonionic surfactants, for example sulfates or sulfonates such as alkylbenzenesulfonates, alkoxylated alkylphenols, for example alkoxylated nonylphenols.

The amount of surfactants in the flooding medium for execution of process step (B) is generally 0.1 to 5 g/l of the formulation, especially 0.5 g/l to 5 g/l, preferably 1 g/l to 5 g/l and more preferably 2 g/l to 5 g/l.

The formulation for execution of process step (B) may additionally optionally comprise further components, for example biocides or clay stabilizers.

To produce the formulation, urea and solid glucan (G), and optionally further constituents, can be dissolved in water. It is, however, advisable to use the abovementioned aqueous glucan solution obtained from the production. The solution can be mixed with the further components in the desired ratio and diluted to the desired concentration. It is also possible to use the further components in predissolved form, i.e., for example, to use an aqueous solution of urea and mix it with an aqueous glucan (G) solution.

Execution of Process Step (B)

To perform process step (B), the formulation mentioned is injected into the formation through the at least one injection well.

The flooding medium used for process step (B) is injected into the formation with a temperature of less than 60° C., preferably less than 35° C., more preferably less than 25° C. and, for example, at about room temperature. The hydrolysis sets in at significant rate when the urea-containing formulation has warmed up in the formation to temperatures of at least 60° C. Naturally, the rate of hydrolysis increases with increasing temperature. Preferred temperatures for at least one partial region of the mineral oil formation between the injection and production wells have already been specified above.

The NH₃ and CO₂ gases formed have different effects in the formation. Some of the NH₃ formed dissolves in the water and forms an alkaline zone, and some of the CO₂ formed dissolves in the oil and increases the mobility thereof. The remaining amounts of gas form foams with the components of the formulation for process step (B), i.e. at least the glucan (G) and optionally the surfactants.

The process according to the invention comprising process step (B) has the advantage that the combination of the thermally stable and salt-stable glucan (G) with urea gives positive synergetic effects in oil recovery. Compared to water flooding, the level of oil recovery is not only improved in a manner known in principle by the use of thickening polymers; instead, the combination with urea achieves additional effects.

The hydrolysis of the urea in the mineral oil formation forms mobile zones (banks) enriched with ammonia and CO₂. The partition coefficient of CO₂ in the oil-water system is about 4 to 10 at 35-100° C. and 100 to 400 bar. There is thus a distinct accumulation of the CO₂ in the mineral oil, and the CO₂ reduces the viscosity of the mineral oil in a manner known in principle.

Furthermore, neutralization of carboxylic acids which occur in the crude oil, for example naphthenic acid and ammonia in situ, forms surfactants in the mineral oil deposit, which improve oil recovery from the mineral oil formation by lowering the oil-water interfacial tension. Naturally, these surfactant effects are particularly advantageous in the case of mineral oils with a high carboxylic acid content. In this process variant, it is particularly advantageous to additionally use ammonium salts. The ammonia formed and the ammonium ions form a buffer which keeps the pH within a range favorable for formation of carboxylic salts.

Finally, foams form with the gases formed. The formation of foams is supported by the glucan, since the escape of gases into shallower zones of the mineral oil deposits is made much more difficult by the viscous polymer solution compared to the use of unthickened water as a flooding medium. The foam phases have a higher viscosity than the unfoamed water phase, as a result of which more homogeneous flooding is achieved. Gas production in the carrier also increases the local formation pressure and hence likewise promotes oil displacement. Since the unfoamed aqueous urea-glucan solution has a lower viscosity than the foam, the aqueous flooding medium after injection first of all flows through the highly permeable zones of the formation. After foam formation, flow through the highly permeable zones becomes much more difficult.

Additional Process Step (A)

The process may optionally comprise at least one additional process step (A) which is executed before a process step (B), and in which flooding media are likewise injected into the deposit through the injection well(s) and mineral oil is withdrawn through at least one production well.

In one embodiment of the invention, the flooding medium is an aqueous flooding medium (process step (A1)). This may be fresh water or salt-containing water. For example, it may be seawater or partly desalinated seawater, or all or some may be salt-containing deposit water which can be injected back into the deposit in this way.

In addition to water, it is optionally possible to use water-miscible organic solvents, but at least 85% by weight, preferably at least 95% by weight, of the solvents used should be water. Preference is given to using exclusively water as the solvent.

The aqueous flooding medium injected may have a low temperature, for example a temperature in the range from 10° C. to 35° C., or about room temperature. Such temperatures generally arise automatically, for example are the temperature of the seawater used for flooding. However, the flooding medium may also be a warmed aqueous flooding medium. For example, it may be water at a temperature of at least 80° C. It may also be superheated water, i.e. liquid water with a temperature of more than 100° C. Naturally, the pressure here is higher than 1 bar; under conditions of injection into a mineral oil formation, a pressure of 1 bar is generally clearly exceeded.

The aqueous flooding medium for process step (A1) may, as well as water or salt water, of course also comprise additional components. More particularly, additional components may be thickening components, especially thickening polymers. Preference may be given here to a glucan (G).

The viscosity of a glucan-containing aqueous flooding medium here should preferably be such that the viscosity of a flooding medium injected in a process step (A1) is lower than the viscosity of the aqueous flooding medium injected in the subsequent process step (B).

In a further embodiment of the invention, the flooding medium injected may be steam (process step (A2)). Steam on injection into the mineral oil deposit may have a temperature of more than 300° C.

Additional Process Step (C)

The process may optionally comprise at least one additional process step (C) which is executed after a process step (B), and in which flooding media are likewise injected into the deposit through the injection well(s) and mineral oil is withdrawn through at least one production well.

In one embodiment of the invention, the flooding medium is an aqueous flooding medium (process step (C1)). This may be fresh water or salt-containing water. For example, it may be seawater or partly desalinated seawater, or all or some may be salt-containing deposit water which can be injected back into the deposit in this way.

In addition to water, it is optionally possible to use water-miscible organic solvents, but at least 85% by weight, preferably at least 95% by weight, of the solvents used should be water. Preference is given to using exclusively water as the solvent.

The aqueous flooding medium injected may have a low temperature, for example a temperature in the range from 10° C. to 35° C., or about room temperature. However, the flooding medium may also be a warmed aqueous flooding medium. For example, it may be water at a temperature of at least 80° C. It may also be superheated water, i.e. liquid water with a temperature of more than 100° C. Naturally, the pressure here is higher than 1 bar; under conditions of injection into a mineral oil formation, a pressure of 1 bar is generally clearly exceeded.

The aqueous flooding medium for process step (C1) may, as well as water or salt water, of course also comprise additional components. More particularly, additional components may be thickening components, especially thickening polymers. Preference may be given here to a glucan (G).

The viscosity of a glucan-containing aqueous flooding medium here should preferably be such that the viscosity of a flooding medium injected in a process step (C1) is higher than the viscosity of the aqueous flooding medium injected in the subsequent process step (B).

In a further embodiment of the invention, the flooding medium injected may be steam (process step (C2)). Steam on injection into the mineral oil deposit may have a temperature of more than 300° C.

Combination of Process Steps (A), (B) and (C)

Process steps (A), (B) and (C) can be combined with one another. The combination may, for example, be one of the following flooding schemes 1 to 4:

Flooding Process step (A1) → Process step (B) → Process step (C1) scheme 1: Aqueous medium Aqueous medium Flooding Process step (A2) → Process step (B) → Process step (C2) scheme 2: Steam Steam Flooding Process step (A2) → Process step (B) → Process step (C1) scheme 3: Steam Aqueous medium Flooding Process step (A1) → Process step (B) → Process step (C2) scheme 4: Aqueous medium Steam

In addition, the sequence of process steps (A)→(B)→(C) can also be repeated cyclically.

Flooding Scheme 1

In flooding scheme 1, flooding is first effected with an aqueous flooding medium, as described above, then the flooding is continued with the flooding medium (B) comprising glucans and urea, and finally flooding is again effected with an aqueous flooding medium.

In this embodiment, the natural deposit temperature should be at least 60° C., preferably at least 70° C., more preferably at least 80° C. and, for example, at least 90° C. It may be 60° C. to 150° C., especially 70° C. to 140° C., preferably 75° C. to 135° C. and more preferably 80° C. to 120° C. This is because any use, in process step (A2), of cold flooding water, i.e., for example, flooding water with a temperature in the range from 10° C. to 35° C., causes the temperature of the mineral oil deposit in the injection site environment to fall gradually over the course of time. The flooding of a deposit with water may take months or even years. Naturally, the cooling is at its greatest at the injection site itself, and the temperature again approaches the natural deposit temperature with increasing distance from the injection site. A sufficient natural deposit temperature ensures that the actual deposit temperature—as required to execute the process—is at least 60° C. at least within a partial region of the mineral oil formation between the injection and production wells.

If avoidance of cooling or at least of excessive cooling is desired, the aqueous flooding medium can be heated before injection, for example to temperatures of at least 80° C.

In a preferred embodiment, flooding is effected in process step (C1) with a flooding medium which has been thickened, preferably likewise with the aid of the glucan (G). The amount of the glucan (G) here should be such that the viscosity of the aqueous flooding medium injected in process step (C1) is greater than the viscosity of the aqueous flooding medium injected in process step (B). Such a measure counteracts the effect of “fingering”. “Fingering” means that a flooding phase of relatively low viscosity does not form a homogeneous flow front to a flooding phase of relatively high viscosity; instead, the flow front is inhomogeneous. The reason for this is essentially that the lower-viscosity flooding phase flows faster through permeable zones, while the flow is slower through less permeable zones. “Fingering” can be substantially avoided when the subsequent flooding phase is more viscous.

In a further preferred embodiment, flooding is effected both in process step (A1) and in process step (C1) with an aqueous flooding medium which has been thickened in each case, preferably with the aid of a glucan (G) in each case, the viscosity of the flooding phase used increasing in the sequence (A1)→(B)→(C1).

Flooding Scheme 2

In flooding scheme 2, flooding is effected first with steam, as described above, then the flooding is continued with the flooding medium (B) comprising glucans and urea, and finally flooding is effected again with steam.

In this embodiment, the natural deposit temperature may also be less than 60° C. The injection of the steam in process step (A)—the steam used for injection typically has temperatures of up to 300° C.—heats the deposit proceeding from the injection well with increasing duration of steam injection, such that, at least in a partial region of the mineral oil formation between the injection and production wells, a temperature of at least 60° C., preferably at least 70° C., more preferably at least 80° C. and, for example, at least 90° C. is attained. It should, however, not exceed 150° C., preferably 135° C. and more preferably 120° C. achieves. If these values are exceeded, commencement of process step (B) should be preceded by intermediate flooding with cold water, for example water with temperatures of 10° C. to 35° C.

Subsequently, process step (B) is executed. The duration of process step (B) can be fixed by the person skilled in the art according to the desired results, but process step (B) is stopped no later than when the temperature in the entire region of the mineral oil formation between the injection and production wells has fallen to temperatures of less than 60° C. It is advisable to stop process step (B) as soon as the temperature goes below 70° C., more preferably when it goes below 80° C.

The process is subsequently continued with the injection of steam (process step (C2)). In order to protect the flooding phase (B), it may also be advisable here for the injection of the steam to be preceded by intermediate flooding with cold water. The intermediate flood may also be thickened, preferably with the aid of a glucan (G). If thickening is effected, the viscosity of the intermediate flood should be at least as high as the flooding phase used for process step (B).

Flooding Scheme 3

In flooding scheme 3, flooding is first effected with steam, as described above, then the flooding is continued with the flooding medium (B) comprising glucans and urea, and then the flooding is continued with an aqueous flooding medium. The natural deposit temperature in flooding scheme 3, as in flooding scheme 2, may also be less than 60° C. because the deposit heats up under the influence of the steam. With regard to the details of steps (A2) and (B), the statements for flooding scheme 2 apply. After process step (B), process step (C1) is performed.

Flooding Scheme 4

In flooding scheme 4, flooding is effected first with an aqueous flooding medium, as described above, then the flooding is continued with the flooding medium (B) comprising glucans and urea, and finally flooding is effected with steam. As in flooding scheme 1, the natural deposit temperature must be at least 60° C. Preferred temperature ranges have already been mentioned for flooding scheme 1. In flooding scheme 4 too, it may be advisable to follow process step (B) with intermediate flooding with cold water, optionally thickened water.

Additional Process Step (D)

By means of additional process step (D), the process according to the invention can be combined with “conformance control” measures.

In mineral oil deposits with particularly heterogeneous permeability, aqueous flooding media or else steam injected flows preferentially through the particularly permeable regions of the formation, from which oil is preferentially recovered as a result, while there is less or even no flow through less permeable regions. Thus, immobilized oil remains in the less permeable regions. This is shown schematically in FIG. 4. An injection well (1) and two production wells (2, 2′) were sunk into a mineral oil deposit. The aqueous flooding medium for process step (B) is injected through injection well (1), flows in the direction of production wells (2, 2′) and pushes the mineral oil onward. What is called the displacement threshold (i.e. the boundary between the aqueous phase and the mineral oil phase) is drawn in schematically (7). The preferred flow paths (3) for the aqueous phase or the mobilized mineral oil are shown by hatching. These are not straight, and instead follow the permeable zones of the formation. Outside the hatched area, unmobilized mineral oil remains. Also drawn in is the 60° C. isotherm (4). Within the enclosed zone, it is colder; outside the zone, it is warmer. In the regions with a temperature from 60° C., the urea begins to hydrolyze and foam formation accordingly commences.

In step (D), in accordance with the invention, a formulation of a thermogel thickened by means of a glucan (G) is injected, i.e. a formulation which can form highly viscous gels after injection under the influence of the formation temperature. The formulation comprises at least one glucan (G), urea and at least one water-soluble aluminum(III) salt and/or a partly hydrolyzed aluminum(III) salt. The water-soluble aluminum(III) salts may, for example, be aluminum chloride, aluminum bromide, aluminum nitrate, aluminum sulfate, aluminum acetate or aluminum acetylacetonate. They may, however, also be already partly hydrolyzed aluminum(III) salts, for example aluminum hydroxychloride. It will be appreciated that it is also possible to use mixtures of several different aluminum compounds. The pH of the formulation should be ≦5, preferably ≦4.5 and more preferably ≦4. Aluminum(III) salts are acidic, and so this pH is generally established of its own accord given sufficient concentrations than Al(III). It would optionally be possible to acidify somewhat further. The compounds are preferably aluminum(III) chloride and/or aluminum(III) nitrate.

The principle of action of such thermogels is that the aluminum(III) salts mentioned form acidic solutions, but form sparingly soluble gels in the alkaline range. The change in the pH is triggered by the hydrolysis of urea at elevated temperatures, at which ammonia forms as already outlined.

A useful amount has been found to be from 0.2 to 3% by weight of aluminum(III), based on the aqueous formulation, and the amount of urea should be such that 3 mol of base are released per mole of Al(III). The rate of gel formation depends naturally on the temperature, because the urea hydrolyzes ever more rapidly with increasing temperature. In addition, the rate of gel formation may depend on the aluminum(III) to urea ratio. Details of this are compiled in the examples section.

When they reach relatively hot zones, the aluminum-urea-glucan formulations form sparingly soluble gels. This is shown schematically in FIG. 5; gel banks (5) have formed here. The previously preferred flow zones are blocked as a result, and injected flooding medium is subsequently forced to flow through less permeable zones from which oil has yet to be recovered in the formation. These new flow paths are shown in FIG. 5 by the arrows (6). This allows further mineral oil to be mobilized.

The thickening of the aluminum-urea solution with the glucan has the effect that the formulation injected, due to the increase in viscosity, cannot mix as easily with the deposit water and with previously injected flooding phase (B) (suppression or at least reduction of “fingering”). In the case of excessive dilution, it would no longer be possible for a high-viscosity gel to form. The thickening allows the flood with the thermogel to pass through longer distances in the formation without being diluted to too great a degree. As a result, gel banks can also be formed at a great distance from the injection well and the formation can thus be blocked at these points.

Further Process Steps

The process may optionally of course comprise further process steps. These firstly include the already mentioned intermediate flooding with water between process steps (A) and (B) and/or (B) and (C). In addition, the process can also be combined with surfactant flooding. Surfactant flooding involves injection of an aqueous formulation of surfactants into the formation, the surfactants reducing the water-oil interfacial tension after injection. Suitable surfactants for use in mineral oil deposits are known to those skilled in the art and are also commercially available. Surfactant flooding can advantageously be performed before execution of process step (B).

One possible sequence of process steps would be, for example, process step (A1)→surfactant flooding→process step (B)→optionally process step (C).

The examples which follow are intended to illustrate the invention in detail:

Preparation of the glucan (G):

Glucan (G) with a β-1,3-glycosidically Linked Main Chain, and β-1,6-glycosidically Bonded Side Groups (Inventive)

The glucan (G) was prepared by means of the in WO 2011/082973 A2, inventive example 1, pages 15 to 16, in the apparatus described. The concentrate obtained was diluted to the temperature desired in each case for the tests.

Comparative Polymer 1:

Commercial synthetic polymer formed from approx. 75 mol % of acrylamide and 25 mol % of the sulfo-containing monomer 2-acrylamido-2-methylpropanesulfonic acid (sodium salt), weight-average molecular weight Mw of approx. 11 million g/mol

Comparative Polymer 2:

Commercial biopolymer xanthan (CAS 11138-66-2) (biopolymer produced by fermentation with the bacterium Xanthamonas Campestris) with a weight-average molecular weight M_(w) of approx. 2 million g/mol.

Comparative Polymer 3:

Commercial biopolymer diutan (biopolymer produced by fermentation with Sphingomonas sp.) The inventive glucan and the comparative polymers were used to perform the viscosity measurements described hereinafter.

Performance of the Viscosity Measurements:

-   -   Test instrument: shear stress-controlled Physica MCR301 rotary         viscometer pressure cell with double-gap geometry DG 35/PR/A1     -   Measurement range: 25 to 170° C., as specified in each case     -   Shear rate: as specified in each case

The complete measurement system including the syringe with which the sample is taken and introduced into the rheometer was purged with nitrogen. During the measurement, the test cell was pressurized with 8 bar of nitrogen.

Test Series 1:

The viscosity of solutions of the glucan (G) (called P1 in the figure) and of comparative polymers V1 and V2 was measured at different concentrations of 0.2 g/l to 2 g/l. The measurements were carried out in synthetic deposit water. For this purpose, the polymers were dissolved in superconcentrated salt water or—in the case that the polymer is already present as solution—a solution of the polymer is mixed with superconcentrated salt water, and the resulting salt solution is subsequently diluted so as to give the concentrations stated below. The measurements of P1 and V2 were performed at 54° C., and the measurement of V1 at 40° C.

Composition of the deposit water (per liter):

CaCl₂ 42 600 mg MgCl₂ 10 500 mg NaCl 132 000 mg Na₂SO₄ 270 mg NaBO₂*4 H₂O 380 mg Total salinity 185 750 mg

The results are compiled in FIG. 1. FIG. 1 shows that glucan P1 achieves the best viscosity efficiency in deposit water, i.e. the samples give the highest viscosity at a given concentration.

Test Series 2:

The viscosity of aqueous solutions of glucan G No. P1 and of comparative polymers V1, V2 and V3 in ultrapure water was measured in a concentration of in each case 3 g/l at a shear rate of 100 s⁻¹ within the temperature range from 25° C. to 170° C. For this purpose, the solution of glucan (G) No. P1 was diluted correspondingly, and polymers V1, V2 and V3 were dissolved in the corresponding concentration in water. The samples were injected into the test cell at room temperature and the heating rate was 1° C./min. The results are shown in FIG. 2.

Test Series 3:

The procedure was as in test series 1, except that the solutions were made up not using ultrapure water but rather synthetic deposit water. The results are compiled in FIG. 3.

Comment for Test Series 2 and 3:

The tests show the advantages of the glucan (G) No. P1 used in accordance with the invention compared to the comparative polymers V1, V2 and V3 at high temperature and high salt concentration. The viscosity of the glucan (G) No. P1 remains constant both in salt-containing water and in ultrapure water at temperatures of 25 to 140° C., and only then begins to decrease gradually. In ultrapure water, both the synthetic polymer V1 (copolymer of acrylamide and 2-acrylamido-2-methylpropanesulfonic acid) and the biopolymer V3 exhibit similar behavior, while the biopolymer V2 is much worse. In deposit water, however, all comparative polymers V1, V2 and V3 are worse than the glucan P1 at relatively high temperatures.

Gas Formation as a Result of Decomposition of Urea

Figure shows the formation of gas bubbles of CO₂ in an aqueous solution of approx. 1.5 g/l glucan (G), 20% by weight of urea and 3% by weight of HCI with the solutions thermostatted at 90° C. The figure shows gas formation after 1, 2 and 3 h.

Formulations for Process Step (D)

For the optional process step (D), formulations composed of water, urea and aluminum salts are used.

Table 1 below shows, by way of example, the time until gel formation for a mixture composed of 8% by weight of AlCl₃ (calculated as anhydrous product, corresponds to 1.6% by weight of Al(III)), 25% by weight of urea and 67% by weight of water.

TABLE 1 Time until gel formation at different temperatures Temperature [° C.] 100 90 80 70 60 Gel formation time [days] ¼ 1 3 6 30

Table 2 below shows the time until gel formation for various mixtures of AlCl₃ (calculated as anhydrous product), urea and water at 100° C. and 100° C. It can be seen that the time for formation of the gel becomes ever longer as the amount of urea decreases.

TABLE 2 Time until gel formation (“—” no measurement). Concentration F1 F2 of the mixture Time until gel AlCl₃ urea [% by wt.] AlCl₃/urea formation [h] [% by wt.] [% by wt.] AlCl₃ urea weight ratio 100° C. 110° C. 8 32 4 16 1:4 4.0 — 8 24 4 12 1:3 4.3 — 8 16 4 8 1:2 7.3 — 8 8 4 4 1:1 19.0 — 16 60 8 30   1:3.75 5.3 2 4 15 2 7.5   1:3.75 — 8 16 48 8 24 1:3 5.5 — 16 32 8 16 1:2 8.3 — 16 16 8 8 1:1 18.0 — 16 12 8 6   1:0.75 23.0 — 

1. A process for producing mineral oil from an underground mineral oil deposit into which at least one production well and at least one injection well have been sunk, each of which is connected to the deposit, said process comprising at least one process step (B) in which mineral oil is produced by injection of an aqueous flooding medium comprising water-soluble thickening polymers through the injection well and withdrawing mineral oil through the production well, wherein the temperature during process step (B) at least in a partial region of the mineral oil formation between the injection and production wells is at least 60° C. and the aqueous flooding medium comprises, as well as water, at least a glucan (G) with a β-1,3-glycosidically linked main chain and side groups β-1,6-glycosidically bonded thereto, said glucan having a weight-average molecular weight M_(w) of 1.5*10⁶ to 25*10⁶ g/mol, and urea.
 2. The process according to claim 1, wherein the aqueous flooding medium used in process step (B) comprises 15 to 300 g/l of urea and 0.1 to 5 g/l of the glucan (G).
 3. The process according to claim 2, wherein the aqueous flooding medium used in process step (B) additionally comprises 50 to 250 g/l of an ammonium salt.
 4. The process according to claim 2, wherein the aqueous flooding medium used in process step (B) additionally comprises 0.1 to 5 g/l of a surfactant.
 5. The process according to claim 1, wherein the temperature at least in a partial region of the mineral oil formation between the injection and production wells is at least 80° C.
 6. The process according to claim 1, wherein the temperature at least in a partial region of the mineral oil formation between the injection and production wells is 80° C. to 120° C.
 7. The process according to claim 1, wherein the process comprises an additional process step (A) which is performed before process step (B), and in which either an aqueous flooding medium (process step (A1)) or steam (process step (A2)) is injected.
 8. The process according to claim 1, wherein the process comprises an additional process step (C) which is performed after process step (B), and in which either an aqueous flooding medium (process step (C1)) or steam (process step (C2)) is injected.
 9. The process according to claim 7, which involves process step (Al) wherein the aqueous flooding medium injected comprises, as well as water, at least one glucan (G), with the proviso that the amount of this glucan (G) is such that the viscosity of the aqueous flooding medium injected in process step (A1) is less than the viscosity of the aqueous flooding medium injected in process step (B).
 10. The process according to claim 8, which involves process step (C1) wherein the aqueous flooding medium injected comprises, as well as water, at least one glucan (G), with the proviso that the amount of this glucan (G) is such that the viscosity of the aqueous flooding medium injected in process step (C1) is greater than the viscosity of the aqueous flooding medium injected in process step (B).
 11. The process according to claim 7, wherein the aqueous flooding media injected in process steps (A1) and/or (C1) have a temperature of at least 80° C.
 12. The process according to claim 7, wherein either steam or an aqueuos flooding medium with a temperature of at least 80° C. is injected in process step (A), and wherein an aqueous flooding medium with a temperature of less than 40° C. is additionally injected between process steps (A) and (B).
 13. The process according to claim 8, wherein either steam or an aqueuos flooding medium with a temperature of at least 80° C. is injected in process step (C), and wherein an aqueous flooding medium with a temperature of less than 40° C. is additionally injected between process steps (B) and (C).
 14. The process according to claim 12, wherein the aqueous flooding media injected between (A) and (B) and/or (B) and (C) comprise at least one glucan (G).
 15. The process according to claim 14, which comprises at least one additional process step (D) for blocking of highly permeable regions of the underground mineral oil formation, and in which an aqueous flooding medium which is injected comprises, as well as water, at least a glucan (G) with a β-1,3-glycosidically linked main chain and side groups β-1,6-glycosidically bonded thereto, said glucan having a weight-average molecular weight M_(w) of 1.5*10⁶ to 25*10⁶ g/mol, urea, and at least one water-soluble aluminum(III) salt and/or a partly hydrolyzed aluminum(III) salt.
 16. The process according to claim 15, wherein process step (D) is performed after process step (B) and then the process is continued with another performance of process step (B). 